Well Treatment Fluids and Methods Utilizing Nano-Particles

ABSTRACT

Disclosed embodiments relate to well treatment fluids and methods that utilize nano-particles. Exemplary nano-particles are selected from the group consisting of particulate nano-silica, nano-alumina, nano-zinc oxide, nano-boron, nano-iron oxide, and combinations thereof. Embodiments also relate to methods of cementing that include the use of nano-particles. An exemplary method of cementing comprises introducing a cement composition into a subterranean formation, wherein the cement composition comprises cement, water and a particulate nano-silica. Embodiments also relate to use of nano-particles in drilling fluids, completion fluids, simulation fluids, and well clean-up fluids.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part of U.S. patentapplication Ser. No. 12/833,189, filed on Jul. 9, 2010, which is adivisional of U.S. patent application Ser. No. 12/472,561, filed on May27, 2009 (now issued as U.S. Pat. No. 7,784,542), which is acontinuation-in-part of U.S. patent application Ser. No. 12/426,645,filed on Apr. 20, 2009 (now issued as U.S. Pat. No. 7,806,183), which isa continuation-in-part of U.S. patent application Ser. No. 11/747,002,filed on May 10, 2007 (now issued as U.S. Pat. No. 7,559,369), theentire disclosures of which are incorporated herein by reference.

BACKGROUND

The example embodiments relate to well treatment compositions andmethods utilizing nano-particles and, more particularly, to well cementcompositions and methods utilizing particulate nano-silica.

In general, well treatments include a wide variety of methods that maybe performed in oil, gas, geothermal and/or water wells, such asdrilling, completion and workover methods. The drilling, completion andworkover methods may include, but are not limited to, drilling,cementing, logging, perforating, fracturing, acidizing, gravel packing,and conformance methods. Many of these well treatments are designed toenhance and/or facilitate the recovery of desirable fluids from asubterranean well.

In cementing methods, such as well construction and remedial cementing,well cement compositions are commonly utilized. For example, insubterranean well construction, a pipe string (e.g., casing and liners)may be run into a well bore and cemented in place using a cementcomposition. The process of cementing the pipe string in place iscommonly referred to as “primary cementing.” In a typical primarycementing method, a cement composition may be pumped into an annulusbetween the walls of the well bore and the exterior surface of the pipestring disposed therein. The cement composition sets in the annularspace, thereby forming an annular sheath of hardened, substantiallyimpermeable cement that supports and positions the pipe string in thewell bore and bonds the exterior surface of the pipe string to thesubterranean formation. Among other things, the annular sheath of setcement surrounding the pipe string functions to prevent the migration offluids in the annulus, as well as protecting the pipe string fromcorrosion. Cement compositions also may be used in remedial cementingmethods, such as squeeze cementing and the placement of cement plugs.

In operation, the annular sheath of cement formed between the well boreand the pipe string often suffers structural failure due to pipemovements which cause shear stresses to be exerted on the set cement.Such stress conditions are commonly the result of relatively high fluidpressures and/or temperatures inside the cemented pipe string duringtesting, perforating, fluid injection or fluid production. For example,such stress may occur in wells subjected to steam recovery or productionof hot formation fluids from high-temperature formations. Thehigh-internal pipe pressure and/or temperature can result in theexpansion of the pipe string, both radially and longitudinally, whichplaces stresses on the cement sheath causing the cement bond between theexterior surfaces of the pipe or the well bore walls, or both, to failand thus allow leakage of formation fluids and so forth. Accordingly, itmay be desirable for the cement composition utilized for cementing pipestrings in the well bores to develop high strength after setting and tohave sufficient resiliency (e.g., elasticity and ductility) to resistloss of the cement bond between the exterior surfaces of the pipe or thewell bore walls, or both. Also, it may be desirable for the cementcomposition to be able to resist cracking and/or shattering that mayresult from other forces on the cement sheath. For example, it may bedesirable for the cement sheath to include structural characteristicsthat protect its structural integrity from forces associated withformation shifting, overburden pressure, subsidence, tectonic creep,pipe movements, impacts and shocks subsequently generated by drillingand other well operations. In addition to including components thatimprove mechanical properties of the cement, in a number of cementingmethods, it may also be desirable to include one or more setaccelerators in the well cement compositions to counteract certainconstituents and/or environmental characteristics that excessively slowset times. For example, among other things, low temperatures and cementadditives (e.g., fluid loss control additives and dispersants) can causeor contribute to an excessive set time for a cement composition.Accordingly, in certain situations, it may be desirable to reduce theset time by including a set accelerator in the cement composition. Thatis, the set accelerator may be included in a cement composition tocounteract components of the cement composition or conditionssurrounding the cement composition that are causing an excessive settime.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present method, and should not be used to limit or define themethod.

The FIGURE depicts an example of a system for delivering treatmentfluids.

DESCRIPTION OF SPECIFIC EMBODIMENTS

The example embodiments relate to well treatment compositions andmethods utilizing nano-particles and, more particularly, to well cementcompositions and methods utilizing particulate nano-silica.

An exemplary embodiment of the cement compositions comprises cement,water and particulate nano-silica. Those of ordinary skill in the artwill appreciate that the exemplary cement compositions generally shouldhave a density suitable for a particular application. By way of example,the cement composition may have a density in the range of from about 4pounds per gallon (“ppg”) to about 20 ppg. In exemplary embodiments, thecement compositions may have a density in the range of from about 8 ppgto about 17 ppg. Exemplary embodiments of the cement compositions may befoamed or unfoamed or may comprise other means to reduce theirdensities, such as hollow microspheres, low-density elastic beads, orother density-reducing additives known in the art. Those of ordinaryskill in the art, with the benefit of this disclosure, will recognizethe appropriate density for a particular application.

Exemplary embodiments of the cement compositions comprise a cement. Anyof a variety of cements suitable for use in subterranean cementingoperations may be used in accordance with exemplary embodiments.Suitable examples include hydraulic cements that comprise calcium,aluminum, silicon, oxygen and/or sulfur, which set and harden byreaction with water. Such hydraulic cements, include, but are notlimited to, Portland cements, pozzolana cements, gypsum cements,high-alumina-content cements, slag cements, silica cements andcombinations thereof. In certain embodiments, the hydraulic cement maycomprise a Portland cement. The Portland cements that may be suited foruse in exemplary embodiments are classified as Class A, C, H and Gcements according to American Petroleum Institute, API Specification forMaterials and Testing for Well Cements, API Specification 10, Fifth Ed.,Jul. 1, 1990.

The water used in exemplary embodiments of the cement compositions maybe freshwater or saltwater (e.g., water containing one or more saltsdissolved therein, seawater, brines, saturated saltwater, etc.). Ingeneral, the water may be present in an amount sufficient to form apumpable slurry. In exemplary embodiments, the water may be present inthe cement compositions in an amount in the range of from about 33% toabout 200% by weight of the cement on a dry basis (“bwoc”). In exemplaryembodiments, the water may be present in an amount in the range of fromabout 35% to about 70% bwoc.

In addition, exemplary embodiments of the cement compositions comprisenano-silica. The nano-silica may be described as particulatenano-silica. That is, the nano-silica may be particulate in nature andnot, for example, a colloidal silica or a suspension of silica insolution. Indeed, in one embodiment, the particulate nano-silica may beadded to the cement composition as a dry nano-silica powder. Generally,the particulate nano-silica may be defined as nano-silica having aparticle size of less than or equal to about 100 nm. For example, theparticulate nano-silica may have a particle size in the range of fromabout 1 nm to about 100 nm (about 1×10⁹ m to about 100×10⁻⁹ m). Incertain exemplary embodiments, the particulate nano-silica may have aparticle size of less than or equal to about 50 nm. For example, theparticulate nano-silica may have a particle size in the range of fromabout 5 nm to about 50 nm. In further exemplary embodiments, theparticulate nano-silica may have a particle size of less than or equalto about 30 nm. For example, the particulate nano-silica may have aparticle size in the range of from about 5 nm to about 30 nm. However,it should be noted that the particulate nano-silica may be utilized incombination with differently sized silica particles in accordance withpresent embodiments. For example, a number of silica particles withparticle sizes greater than 100 nm may be included in a cementcomposition in accordance with present embodiments.

It is now recognized that the particulate nano-silica utilized withpresent embodiments, which may include silicon dioxide, may have animpact on certain physical characteristics of resulting cements. Forexample, relative to inclusion of colloidal silica or larger silicaparticles in a cement slurry, inclusion of particulate nano-silica inthe cement slurry may provide improved mechanical properties, such ascompressive strength, tensile strength, Young's modulus and Poisson'sratio. In addition, the particulate nano-silica also may be included inthe cement composition as a set accelerator to accelerate the set timeof the resultant cement composition. Accordingly, a cement compositionin accordance with present embodiments may comprise a sufficient amountof particulate nano-silica to provide the desired characteristics in aresulting cement. In exemplary embodiments, the particulate nano-silicamay be present in the cement composition in an amount in the range offrom about 1% to about 25% bwoc. In exemplary embodiments, theparticulate nano-silica may be present in the cement composition in anamount in the range of from about 5% to about 15% bwoc.

Other additives suitable for use in subterranean cementing operationsalso may be added to exemplary embodiments of the cement compositions.Examples of such additives include, strength-retrogression additives,set accelerators, weighting agents, weight-reducing additives,heavyweight additives, lost-circulation materials, filtration-controladditives, dispersants, defoaming agents, foaming agents, andcombinations thereof. Specific examples of these, and other, additivesinclude crystalline silica, amorphous silica, salts, fibers, hydratableclays, vitrified shale, microspheres, fly ash, lime, latex, thixotropicadditives, combinations thereof and the like. A person having ordinaryskill in the art, with the benefit of this disclosure, will readily beable to determine the type and amount of additive useful for aparticular application and desired result.

As will be appreciated by those of ordinary skill in the art, exemplaryembodiments of the cement compositions may be used in a variety ofsubterranean applications, including primary and remedial cementing.Exemplary embodiments of the cement compositions may be introduced intoa subterranean formation and allowed to set therein. Exemplaryembodiments of the cement compositions may comprise cement, water andthe particulate nano-silica. By way of example, in exemplary primarycementing embodiments, a cement composition may be introduced into aspace between a subterranean formation and a pipe string located in thesubterranean formation. The cement composition may be allowed to set toform a hardened mass in the space between the subterranean formation andthe pipe string. In addition, in exemplary remedial cementingembodiments, a cement composition may be used, for example, insqueeze-cementing operations or in the placement of cement plugs. One ormore hydrocarbons (e.g., oil, gas, etc.) may be produced from a wellbore penetrating the subterranean formation.

While the preceding discussion is directed to the use of particulatenano-silica, those of ordinary skill in the art will also appreciatethat it may be desirable to utilize other types of nano-particles, inaccordance with embodiments. Examples of such nano-particles includenano-alumina, nano-zinc oxide, nano-boron, nano-iron oxide andcombinations thereof. In certain exemplary embodiments, thenano-particles may be particulate in nature and not, for example, acolloidal nano-particle or a suspension of the nano-particle insolution. Furthermore, while the preceding discussion is directed to theuse of particulate nano-silica in well cementing methods, those ofordinary skill in the art will appreciate that the present techniquealso encompasses the use of nano-particles in any of a variety ofdifferent subterranean treatments. For example, the nano-particles maybe included in any of a number of well treatment fluids that may be usedin subterranean treatments, including drilling fluids, completionfluids, stimulation fluids and well clean-up fluids. In accordance withanother embodiment, the nano-particles may be included as proppant in awell treatment fluid. For example, a well treatment fluid containing thenano-particles may be introduced into a subterranean formation at orabove a pressure sufficient to create or enhance or more fractures inthe subterranean formation. Enhancing a fracture includes enlarging apre-existing fracture in the formation. At least a portion of thenano-particles may be deposited in the one or more fractures such thatthe fractures are prevented from fully closing upon the release ofpressure, forming conductive channels through which fluids may flow to(or from) the well bore.

With regard to fracturing fluids, these fluids are commonly viscosified,gelled and/or crosslinked. The function of the fracturing fluid is usedto apply pressure to the formation rocks around the well, up to apressure whereby the formation is fractured. One essential function ofthese fluids is to be capable of suspending a proppant and especially tocarry this proppant without settling into the fracture created by thefluid. Once again the rheology, especially the so called “suspension”property, and the stability of these fluids is of first importance, aswell as the property of fluid loss control.

In addition to the use of the nano-particles without encapsulation,embodiments may include encapsulation of the nano-particles tofacilitate transportation and incorporation of the nano-particles inwell treatment fluids (e.g., cement compositions). Specifically,encapsulation of the nano-particles in accordance with presentembodiments may include enclosing the nano-particles within an outercoating or container in particulate form. Exemplary methods ofencapsulation are set forth in U.S. Pat. Nos. 5,373,901; 6,444,316;6,527,051; 6,554,071; 7,156,174; and 7,204,312, the relevant disclosuresof which are incorporated herein by reference.

Various types of encapsulation may be employed such that thenano-particles (e.g., the particulate nano-silica) are contained butretains its particulate nature and, thus, retains its correspondingimpact on physical properties of cement slurries. For example, thenano-particles may be encapsulated within a bag, capsule, layer, coatingor the like. Further, the material utilized to encapsulate thenano-particles may be selected to facilitate transportation and/orincorporation of the nano-particles into a well treatment fluid. Forexample, to facilitate handling of the nano-particles and/or tofacilitate timed release of the nano-particles, the encapsulationmaterial may be degradable. This may facilitate handling of thenano-particles by allowing inclusion of the encapsulated nano-particlesin a well treatment fluid without requiring that the nano-particlesfirst be removed from the encapsulating material. Further, theencapsulating material may be designed to degrade at a certain rate whenin contact with certain materials (e.g., water) so that thenano-particles are released into the well treatment fluid at a desiredtime. Exemplary water-dissolvable materials that may be utilized toencapsulate the nano-particles are described in U.S. Pat. Nos. 4,961,790and 5,783,541, the relevant disclosures of which are incorporated hereinby reference.

In accordance with exemplary embodiments, the cement compositions mayutilize a packing volume fraction suitable for a particular applicationas desired. As used herein, the term “packing volume fraction” refers tothe volume of the particulate materials in a fluid divided by the totalvolume of the fluid. The size ranges of the preferred particulatematerials are selected, as well as their respective proportions, inorder to provide a maximized packing volume fraction so that the fluidis in a hindered settling state. It is known that, in such a state, theparticulate materials behave “collectively” like a porous solidmaterial. The hindered settling state is believed to correspond, inpractice, to a much higher solid material concentration in the fluidthan that present in the some traditional cement compositions.

The present embodiments may include a combination of at least threefeatures to obtain a maximum packing volume fraction. One is the use ofat least three particulate materials wherein at least three particulatematerials are in size ranges “disjointed” from one another. In someembodiments, each of the three particulate materials may include adifferent particle size selected from the following ranges: about 7 nmto about 50 nm, about 0.05 microns to about 0.5 microns, 0.5 microns toabout 10 microns, about 10 microns to about 20 microns, about 20 micronsto about 200 microns, about 200 microns to about 800 microns, andgreater than about 1 millimeter. For example, a first particulatematerial may include particles sized from about 7 nm to about 50 nm, asecond particulate material may include particles sized from about 0.05microns to about 0.5 microns, and a third particulate material mayinclude particles sized from about 10 microns to about 20 microns. Inaccordance with present embodiments, the first particulate materialincludes at least one of nano-silica, nano-alumina, nano-zinc oxide,nano-boron, nano-iron oxide or combinations thereof. Another feature ofpresent embodiments may include a choice of the proportions of the threeparticulate materials in relation to the mixing, such that the fluid,when mixed, is in a hindered settling state. Another feature may includethe choice of the proportions of the three particulate materials betweeneach other, and according to their respective size ranges, such that themaximum packing volume fraction is at least substantially achieved forthe sum total of all particulate materials in the fluid system. Packingvolume fraction is described in further detail in U.S. Pat. Nos.5,518,996 and 7,213,646, the relevant portions of which are incorporatedherein by reference.

In various embodiments, systems configured for delivering the treatmentfluids described herein to a downhole location are described. In variousembodiments, the systems can comprise a pump fluidly coupled to atubular, the tubular containing a treatment fluid comprising a proppantcomprising nano-particulates.

The pump may be a high pressure pump in some embodiments. As usedherein, the term “high pressure pump” will refer to a pump that iscapable of delivering a fluid downhole at a pressure of about 1000 psior greater. A high pressure pump may be used when it is desired tointroduce the treatment fluid to a subterranean formation at or above afracture gradient of the subterranean formation, but it may also be usedin cases where fracturing is not desired. In some embodiments, the highpressure pump may be capable of fluidly conveying particulate matter,such as proppant particulates, into the subterranean formation. Suitablehigh pressure pumps will be known to one having ordinary skill in theart and may include, but are not limited to, floating piston pumps andpositive displacement pumps.

In other embodiments, the pump may be a low pressure pump. As usedherein, the term “low pressure pump” will refer to a pump that operatesat a pressure of about 1000 psi or less. In some embodiments, a lowpressure pump may be fluidly coupled to a high pressure pump that isfluidly coupled to the tubular. That is, in such embodiments, the lowpressure pump may be configured to convey the treatment fluid to thehigh pressure pump. In such embodiments, the low pressure pump may “stepup” the pressure of the treatment fluid before it reaches the highpressure pump.

In some embodiments, the systems described herein can further comprise amixing tank that is upstream of the pump and in which the treatmentfluid is formulated. In various embodiments, the pump (e.g., a lowpressure pump, a high pressure pump, or a combination thereof) mayconvey the treatment fluid from the mixing tank or other source of thetreatment fluid to the tubular. In other embodiments, however, thetreatment fluid can be formulated offsite and transported to a worksite,in which case the treatment fluid may be introduced to the tubular viathe pump directly from its shipping container (e.g., a truck, a railcar,a barge, or the like) or from a transport pipeline. In either case, thetreatment fluid may be drawn into the pump, elevated to an appropriatepressure, and then introduced into the tubular for delivery downhole.

The FIGURE shows an illustrative schematic of a system that can delivertreatment fluids of the present invention to a downhole location,according to one or more embodiments. It should be noted that while theFIGURE generally depicts a land-based system, it is to be recognizedthat like systems may be operated in subsea locations as well. Asdepicted in the FIGURE, system 1 may include mixing tank 10, in which atreatment fluid of the present invention may be formulated. Thetreatment fluid may be conveyed via line 12 to wellhead 14, where thetreatment fluid enters tubular 16, tubular 16 extending from wellhead 14into subterranean formation 18. Upon being ejected from tubular 16, thetreatment fluid may subsequently penetrate into subterranean formation18. Pump 20 may be configured to raise the pressure of the treatmentfluid to a desired degree before its introduction into tubular 16. It isto be recognized that system 1 is merely exemplary in nature and variousadditional components may be present that have not necessarily beendepicted in the FIGURE in the interest of clarity. Non-limitingadditional components that may be present include, but are not limitedto, supply hoppers, valves, condensers, adapters, joints, gauges,sensors, compressors, pressure controllers, pressure sensors, flow ratecontrollers, flow rate sensors, temperature sensors, and the like.

Although not depicted in the FIGURE, the treatment fluid may, in someembodiments, flow back to wellhead 14 and exit subterranean formation18. In some embodiments, the treatment fluid that has flowed back towellhead 14 may subsequently be recovered and recirculated tosubterranean formation 18.

It is also to be recognized that the disclosed treatment fluids may alsodirectly or indirectly affect the various downhole equipment and toolsthat may come into contact with the treatment fluids during operation.Such equipment and tools may include, but are not limited to, wellborecasing, wellbore liner, completion string, insert strings, drill string,coiled tubing, slickline, wireline, drill pipe, drill collars, mudmotors, downhole motors and/or pumps, surface-mounted motors and/orpumps, centralizers, turbolizers, scratchers, floats (e.g., shoes,collars, valves, etc.), logging tools and related telemetry equipment,actuators (e.g., electromechanical devices, hydromechanical devices,etc.), sliding sleeves, production sleeves, plugs, screens, filters,flow control devices (e.g., inflow control devices, autonomous inflowcontrol devices, outflow control devices, etc.), couplings (e.g.,electro-hydraulic wet connect, dry connect, inductive coupler, etc.),control lines (e.g., electrical, fiber optic, hydraulic, etc.),surveillance lines, drill bits and reamers, sensors or distributedsensors, downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers, cement plugs, bridge plugs, and otherwellbore isolation devices, or components, and the like. Any of thesecomponents may be included in the systems generally described above anddepicted in the FIGURE.

To facilitate a better understanding of the present technique, thefollowing examples of some specific embodiments are given. In no wayshould the following examples be read to limit, or to define, the scopeof the invention.

Example 1

Five different cement slurries (i.e., Slurry A, Slurry B, Slurry C,Slurry D and Slurry E) were prepared. The slurries and resulting setcements were then tested to determine setting or thickening times andother physical properties of each of the five different slurries. As setforth below, the respective test results for the five different slurriesdemonstrate that inclusion of particulate nano-silica in the slurryreduces the set time and increases the strength of the resulting cementrelative to cements resulting from inclusion of the other silicacomponents that were tested.

Slurries A, B, C and D were prepared by dry blending dry components withcement prior to adding water to form the respective slurry. Slurry E wasprepared by dry blending dry components with cement prior to addingwater and then adding colloidal silica to form the respective slurry.Further, each of the five slurries included a different type of silica.Two of the five slurries included particulate nano-silica in accordancewith present embodiments, and the other three included silica indifferent forms and sizes (e.g., colloidal silica and micro-silica).While the silica included in each of the five slurries was different,the other components utilized in each of the five slurries were similar.Specifically, in addition to a specific type of silica, each of the fiveslurries included 100% bwoc of Class G cement, 0.5% bwoc of a retarder,and sufficient water to make the density of the slurry approximately12.00 lbs/gal. The specific retarder utilized in the slurries was HR-5cement retarder, which is a sulfomethylated lignosulfonate. It should benoted that HR5 cement retarder is available from Halliburton EnergyServices, Inc. and is described in U.S. Pat. No. RE31,190.

As set forth above, each of the five slurries included a different typeof silica and sufficient water to make the resulting slurry have adensity of 12.00 ppg. Slurries A and B included particulate nano-silicain accordance with present embodiments and 15.36 gal/sk of water.Specifically, Slurry A included 15% bwoc of particulate nano-silicahaving a particle size of approximately 30 nm, and Slurry B includedparticulate nano-silica having a particle size of approximately 10 nm.Slurry C included 15% bwoc of SILICALITE cement additive and 15.68gal/sk of water. SILICALITE (compacted) cement additive, which isavailable from Halliburton Energy Services, Inc., Duncan, Okla., is anamorphous silica generally sized in a range from about 2.5 microns toabout 50 microns. Slurry D included 15% bwoc of MICROSAND cementadditive and 15.77 gal/sk of water. MICROSAND cement additive, which isavailable from Halliburton Energy Services, Inc., Duncan, Okla., is acrystalline silica ground to a substantially uniform particle sizedistribution of approximately 5 to 10 microns. Slurry E included 5.12gal/sk of GasCon 469™ lightweight cement additive and 10.09 gal/sk ofwater. GASCON 469 lightweight cement additive is available fromHalliburton Energy Services, Inc., Duncan, Okla., and may be defined asa colloidal silicic acid suspension containing suspended silicic acidparticles generally having a particle size of less than about 20 nm.

After the five slurries were prepared, tests were performed to determinevarious physical characteristics associated with inclusion of thedifferent silica components in each of the associated cementcompositions. One of these tests was performed to measure a thickeningtime associated with each of the five slurries. Specifically, the totalthickening time (TTT) associated with each cement slurry was determinedby performing a thickening-time test in accordance with API RecommendedPractice 10, API Specification for Materials and Testing for WellCements. The measurement of the TTT for each slurry was based on therespective slurry reaching a consistency of 70 Bearden units (Bc) at 80°F. The results of these measurements are set forth for each of the fiveslurries in Table 1 below.

Additional tests were performed on the cement slurries to determineforce-resistance properties (e.g., compressive strength, shear-bondstrength, and tensile strength) for each of the slurries. Each of theforce-resistance property tests was performed on the respective cementslurries at a temperature of 80° F. and after the slurries had set for72 hours. The force-resistance property tests included nondestructiveand destructive ultrasonic strength tests, a compressive-strength test,a shear-bond test, and a tensile-strength test. The nondestructive anddestructive ultrasonic analyzer tests were conducted using a UCAultrasonic cement analyzer to determine a UCA_(72 hrs) value and aUCA_(crush) value, respectively. The compressive-strength tests and UCAanalyzer tests were performed in accordance with API RecommendedPractice 10B. Further, shear-bond and Brazilian-tensile-strength testswere performed to determine shear strength and tensile strength values,respectively, for the different cement compositions. Theshear-bond-strength tests were performed as described in SPE 764entitled “A Study of Cement—Pipe Bonding” by L. G. Carter and G. W.Evans. The Brazilian-tensile-strength tests were performed in accordancewith ASTM C496-96. The results of the tests performed on each of thefive compositions are shown in Table 1 below.

TABLE 1 Shear- Brazilian TTT Comp. Bond Tensile Silica to 70 BcUCA_(72 hrs) UCA_(crush) Strength Strength Strength Slurry Type (Hr:Min)(psi) (psi) (psi) (psi) (psi) Slurry A 30 nm 2:43 328 419 428 169 148.28particulate nano-silica Slurry B 10 nm 5:00 500 481 402 51 14.72particulate nano-silica Slurry C Amorphous 14:32  266 206 211 98 95.5silica Slurry D Crystalline 20:00+ 260 285 252 37.2 102.16 Silica SlurryE Colloidal 20:00+ 225 219 374 42.4 84.71 Silica

Example 2

Samples of Slurries A, C, D and E discussed above were also tested todetermine various additional physical properties associated with theresulting set cements and to confirm relative differences demonstratedabove. While different instruments and calibration settings were used inthe additional testing of the slurries, the test data indicates thatrelative differences between the different slurries are similar to thosedifferences illustrated in Example 1. Indeed, as indicated above inExample 1, the respective test results in Example 2 for the fivedifferent cements demonstrate that inclusion of particulate nano-silicain the cement composition increases the strength of the resulting cementrelative to cements resulting from inclusion of the other silicacomponents that were tested.

Three samples for each of the three conventional cement slurries (SlurryC, Slurry D, and Slurry E) and four samples of Slurry A were tested todetermine compressive strength, Young's modulus, and Poisson's ratio.The compressive-strength tests were performed in accordance with APISpecification 10. It should be noted that the compressive-strengthmeasurements in Example 1 are different than those in Example 2 becausedifferent equipment and different calibrations were utilized. However,the relative differences between compressive strengths for each of thefive slurries are similar. The Young's modulus and Poisson's ratio werestatically determined by means of compression testing using a loadframe. The Young's modulus or modulus of elasticity for each sample wasobtained by taking a ratio of a simple tension stress applied to eachsample to a resulting strain parallel to the tension in that sample. ThePoisson's ratio for each sample was determined by calculating a ratio oftransverse strain to a corresponding axial strain resulting fromuniformly distributed axial stress below a proportional limit of eachsample. The values determined for the three samples of each of the fivedifferent cement slurries are set forth below in Table 2.

TABLE 2 Com- pressive Silica Strength Young's Poisson's Slurry SampleType (psi) Modulus Ratio Slurry A Sample 1 30 nm 1257 2.26E+05 **particulate nano-silica Slurry A Sample 2 30 nm 1189 2.12E+05 0.109particulate nano-silica Slurry A Sample 3 30 nm 1249 2.04E+05 0.092particulate nano-silica Slurry A Sample 4 30 nm 1275 2.13E+05 0.110particulate nano-silica Slurry C Sample 1 Amorphous 466 2.53E+05 0.064silica Slurry C Sample 2 Amorphous 483 2.38E+05 0.064 silica Slurry CSample 3 Amorphous 506 2.40E+05 0.053 silica Slurry D Sample 1Crystalline 350 1.42E+05 0.068 Silica Slurry D Sample 2 Crystalline 3971.50E+05 0.063 Silica Slurry D Sample 3 Crystalline 378 1.46E+05 0.060Silica Slurry E Sample 1 Colloidal 514 1.03E+05 0.063 Silica Slurry ESample 2 Colloidal 598 1.15E+05 0.072 Silica Slurry E Sample 3 Colloidal627 1.23E+05 0.071 Silica

The particular embodiments disclosed above are illustrative only, as theexample embodiments may be susceptible to various modifications andalternative forms. However, it should be understood that the embodimentsare not intended to be limited to the particular embodiments disclosed.Rather, the embodiments cover all modifications, equivalents andalternatives falling with the scope and spirit of the present inventionas defined by the following appended claims. In addition, every range ofvalues (of the form, “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed in the present Description of Specific Embodiments is to beunderstood as referring to the power set (the set of all subsets) of therespective range of values, and set for the every range encompassedwithin the broader range of value.

What is claimed is:
 1. A method of treating a subterranean formation comprising: introducing into the subterranean formation a treatment fluid at or above a pressure sufficient to create or enhance one or more fractures in the subterranean formation wherein at least a portion of the treatment fluid contains a proppant comprising nano-particulates; and depositing at least a portion of the nano-particulates in the one or more fractures, wherein the fractures are prevented from fully closing upon the release of pressure.
 2. The method of claim 1, wherein the fractures form conductive channels through which fluids may flow.
 3. The method of claim 1, wherein the nano-particulates comprise nano-silica.
 4. The method of claim 1, wherein the nano-particulates comprise a particulate nano-silica.
 5. The method of claim 1, wherein the proppant comprises a particulate blend of at least particles less than 0.5 microns and particulates greater than 1 millimeter.
 6. The method of claim 1, wherein the nano-particulates have a particle size of less than or equal to about 100 nm.
 7. The method of claim 1, wherein the nano-particulates have a particle size in the range of from about 1 nm to about 100 nm.
 8. The method of claim 1, wherein the nano-particulates are coated.
 9. The method of claim 1, wherein the nano-particulates are selected from the group consisting of nano-aluminum, nano-zinc oxide, nano-boron, nano-iron oxide and combinations thereof.
 10. The method of claim 1, further comprising producing one or more hydrocarbons from a well bore penetrating the subterranean formation.
 11. The method of claim 1, wherein the treatment fluid comprises at least one member selected from the group consisting of a gelling agent and a crosslinking agent.
 12. A fracturing fluid comprising a nano-sized proppant.
 13. The fracturing fluid of claim 12, wherein the nano-sized proppant prevents fractures in a subterranean formation from fully closing upon the release of pressure therefrom.
 14. The fracturing fluid of claim 12, wherein the nano-sized proppant has a particle size of less than or equal to about 100 nm.
 15. The fracturing fluid of claim 12, wherein the nano-sized proppant has a particle size in the range of from about 1 nm to about 100 nm.
 16. The fracturing fluid of claim 12, wherein the nano-sized proppant is coated.
 17. The fracturing fluid of claim 12, wherein the nano-sized proppant comprises nano-silica.
 18. The fracturing fluid of claim 12, wherein the nano-sized proppant comprises a particulate nano-silica.
 19. The fracturing fluid of claim 12, wherein the nano-sized proppant is selected from the group consisting of nano-aluminum, nano-zinc oxide, nano-boron, nano-iron oxide and combinations thereof.
 20. The fracturing fluid of claim 12, wherein the fracturing fluid comprises at least one member selected from the group consisting of a gelling agent and a crosslinking agent.
 21. A method of treating a subterranean formation comprising: introducing into the subterranean formation a treatment fluid comprising particulate materials, the particulate materials comprising a particulate having a particle size of less than or equal to about 100 nm; and determining a packing volume fraction for the particulate materials in the treatment fluid. 